This invention relates to recovery of oil and gas from wells, more particularly to hydraulic fracturing and gravel packing, and most particularly to decreasing fluid loss and damage due to fluid loss additives when using viscoelastic surfactant fluid systems as carrier fluids.
There are many oilfield applications in which filter cakes are needed in the wellbore, in the near-wellbore region or in one or more strata of the formation. Such applications are those in which, without a filter cake, fluid would leak off into porous rock at an undesirable rate during a well treatment. Such treatments include drilling, drill-in, completion, stimulation (for example, hydraulic fracturing or matrix dissolution), sand control (for example gravel packing, frac-packing, and sand consolidation), diversion, scale control, water control, and others. When the filter cake is within the formation it is typically called an “internal” filter cake; otherwise it is called an “external” filter cake. Typically, after these treatments have been completed the continued presence of the filter cake is undesirable or unacceptable.
Hydraulic fracturing, gravel packing, or fracturing and gravel packing in one operation (called, for example frac and pack or frac-n-pack, or frac-pack treatments), are used extensively to stimulate the production of hydrocarbons, water and other fluids from subterranean formations. These operations involve pumping a slurry of “proppant” (natural or synthetic materials that prop open a fracture after it is created) in hydraulic fracturing or “gravel” in gravel packing. In low permeability formations, the goal of hydraulic fracturing is generally to form long, high surface area fractures, that greatly increase the magnitude of the pathway of fluid flow from the formation to the wellbore. In high permeability formations, the goal of a hydraulic fracturing treatment is typically to create a short, wide, highly conductive fracture, in order to bypass near-wellbore damage done in drilling and/or completion, to ensure good fluid communication between the rock and the wellbore and also to increase the surface area available for fluids to flow into the wellbore. Gravel is also a natural or synthetic material, which may be identical to, or different from, proppant. Gravel packing is used for “sand” control. Sand is the name given to any particulate material, such as clays, from the formation that could be carried into production equipment. Gravel packing is a sand-control method used to prevent production of formation sand, in which, for example a steel screen is placed in the wellbore and the surrounding annulus is packed with prepared gravel of a specific size designed to prevent the passage of formation sand that could foul subterranean or surface equipment and reduce flows. The primary objective of gravel packing is to stabilize the formation while causing minimal impairment to well productivity. Sometimes gravel packing is done without a screen. High permeability formations are frequently poorly consolidated, so that sand control is needed. Therefore, hydraulic fracturing treatments in which short, wide fractures are wanted are often combined in a single continuous (“frac and pack”) operation with gravel packing. For simplicity, in the following we may refer to any one of hydraulic fracturing, fracturing and gravel packing in one operation (frac and pack), or gravel packing, and mean them all.
Solid, substantially insoluble, or sparingly or slowly soluble, materials (that may be called fluid loss additives and/or filter cake components) are typically added to the fluids used in these treatments to form the filter cakes, although sometimes soluble (or at least highly dispersed) components of the fluids (such as polymers or crosslinked polymers) may form some or all of the filter cakes. Removal of the filter cake is typically accomplished either by a mechanical means (scraping, jetting, or the like), by subsequent addition of a fluid containing an agent (such as an acid, a base, an oxidizer, or an enzyme) that dissolves at least a portion of the filter cake, or by manipulation of the physical state of the filter cake (by emulsion inversion, for example). These removal methods usually require a tool or addition of another fluid (for example to change the pH or to add a chemical). This can sometimes be accomplished in the wellbore but normally cannot be done in a proppant or gravel pack. Sometimes the operator may rely on the flow of produced fluids (which will be in the opposite direction from the flow of the fluid when the filter cake was laid down) to loosen the filter cake or to dissolve at least a part of the filter cake (for example if it is a soluble salt). However, these methods require fluid flow and often result in slow or incomplete filter cake removal. Sometimes a breaker can be incorporated in the filter cake but these must normally be delayed (for example by esterification or encapsulation) and they are often expensive and/or difficult to place and/or difficult to trigger.
In hydraulic fracturing, a first, viscous fluid called a “pad” is typically injected into the formation to initiate and propagate the fracture and often to contribute to fluid loss control. The choice of the pad fluid depends upon the nature of the subsequently injected fluid and of the formation and on the desired results and attributes of the stimulation job.
This is typically followed by a second fluid designed primarily to carry the proppant that keeps the fracture open after the pumping pressure is released. Occasionally, hydraulic fracturing is done with a second fluid that is not highly viscosified; this choice is made primarily to save chemical costs and/or as a way to reduce the deleterious effect of polymers described below. This technique, sometimes called a “water-frac” involves using extremely low polymer concentrations, so low that they cannot be effectively crosslinked, throughout the job. This alternative has a major drawback: since there is inadequate viscosity to carry much proppant, high pump rates must be used and only very small concentrations (pounds mass proppant added per gallon of fluid), called “PPA”, of proppant can be used. Very little proppant will be placed in the fracture to keep it open after the pumping is stopped.
Pads and fracturing or gravel packing fluids are usually viscosified in one of three ways. If the injected fluid is an oil, it is gelled with certain additives designed for the purpose, such as certain aluminum phosphate compounds; this will not be discussed further here. If the fluid is water or brine, for hydraulic or acid fracturing, it is gelled with polymers (usually polysaccharides like guars, usually crosslinked with a boron, zirconium or titanium compound), or with viscoelastic fluid systems (“VES's”) that can be formed using certain surfactants that form appropriately sized and shaped micelles. VES's are popular because they leave very clean proppant or gravel packs, but they don't form a filter cake by themselves. Polymers, especially crosslinked polymers, often tend to form a “filter cake” on the fracture face, that is they coat out on the fracture face as some fluid leaks off, provided that the rock pores are too small to permit entry of the polymer or crosslinked polymer. Some filter cake is generally desirable for fluid loss control. This process of filter cake formation is also called wallbuilding. VES fluids without fluid loss additives do not form filter cakes as a result of leak-off. VES leak-off control, in the absence of fluid loss additives, is viscosity controlled, i.e., the resistance due to the flow of the viscous VES fluid through the formation porosity limits the leak-off rate. The viscosity controlled leak-off rate can be high in certain formation permeabilities because the highly shear-thinning fluid has a low apparent viscosity in high flow velocity areas. Reducing the flow velocity (by correspondingly reducing the pressure gradient or simply as a result of the same injected volumetric flow rate leaking off into the formation through a greater surface area as the fracture grows in length and height) will allow micelle structure to reassemble and will result in regeneration of viscosity and fluid loss control. Fluid loss control may not always be optimal with VES systems, especially in higher permeability formations. On the other hand, polymers have two major deficiencies: a) the filter cake, if left in place, can impede subsequent flow of hydrocarbons into the fracture and then into the wellbore, and b) polymer or crosslinked polymer will be left in the fracture itself, impeding or cutting off flow, either by physically blocking the flow path through the proppant pack or by leaving a high viscosity fluid in the fracture. VES fluids do not form a filter cake or leave solids in the fracture. VES fluids therefore leave a cleaner, more conductive and therefore more productive fracture. They are easier to use because they require fewer components and less surface equipment, but they may be less efficient than polymers, depending upon the formation permeability and the specific VES system. It would be desirable to make the use of VES fluid systems more efficient.
Instead of conventional fluid loss additives and filter cake formation, it is known to treat a subterranean formation by pumping a colloidal suspension of small particles in a viscoelastic surfactant fluid system; see for example U.S. patent application Ser. No. 10/707,011, filed Nov. 13, 2003, and assigned to the assignee of the present application. The colloidal suspension and the viscoelastic surfactant interact to form structures that effectively bridge and block pore throats. Colloidal suspensions are typically dispersions of discrete very small particles, spherical or elongated in shape, charged so that the repulsion between similarly charged particles stabilizes the dispersion. Disturbance of the charge balance, due for instance to removing the water, changing the pH or adding salt or water-miscible organic solvent, causes the colloidal particles to aggregate, resulting in the formation of a gel. These particles are typically less than 1 micron in size, and typically in the range from about 10 to about 100 nanometers. The dispersion is prepackaged as a liquid, transparent in the case of relatively low concentrations of particles, becoming opalescent or milky at higher concentrations. In any case, the dispersion may be handled as a liquid, which greatly simplifies the dosage.
The use of a hydrolysable polyester material for use as a fluid loss additive for fluid loss control has previously been proposed for polymer-viscosified fracturing fluids. After the treatment, the fluid loss additive degrades and so contributes little damage. Further, degradation products of such materials have been shown to cause delayed breaking of polymer-viscosified fracturing fluids. U.S. Pat. No. 4,715,967 discloses the use of polyglycolic acid (PGA) as a fluid loss additive to temporarily reduce the permeability of a formation. SPE paper 18211 discloses the use of PGA as a fluid loss additive and gel breaker for crosslinked hydroxypropyl guar fluids. U.S. Pat. No. 6,509,301 describes the use of acid forming compounds such as PGA as delayed breakers of surfactant-based vesicle fluids, such as those formed from the zwitterionic material lecithin. The preferred pH of these materials is above 6.5, more preferably between 7.5 and 9.5.
Since VES fluid systems cause negligible damage, it would be desirable to use a fluid loss additive that is compatible with the VES system and also causes negligible damage. It would be desirable to use polyglycolic acid and similar materials as a fluid loss additive for VES fluid systems, but this creates a problem because these materials often contain small amounts of acid as commercially obtained and furthermore these materials typically start to hydrolyze to form acids as they are being used. The acid contained or generated by the material decreases the pH of the VES fluid system; this typically decreases the viscosity, because the viscosity of many VES fluid systems is quite pH sensitive. Therefore, simply adding the PGA or similar material to the VES fluid system would not be an acceptable solution to the problem. Inherently present monomeric acid or early dissolution of some of the PGA or similar material would deleteriously affect the viscosity of the system.
In some cases viscous fluids are used in treatments in which some or all of the fluid may be allowed to invade the formation, in which case a component is needed that is a breaker but not a fluid loss additive.
The objective of the current invention is to provide a fluid loss additive and/or breaker for VES fluid systems that retards fluid loss to the formation, does not affect the viscosity during the job, but still allows complete cleanup of the formation or the proppant or gravel pack.